This NACE standard test method applies to the internal surfaces of pipelines, and describes types of microorganisms, mechanisms by which MIC occurs, methods for sampling and testing for the presence of microorganisms, research results, and interpretation of test results. Sections 1 through 4 of this standard discuss the technical aspects of MIC. Sections 5 through 7 discuss field equipment and testing procedures. This standard is maintained by Task Group 254.
Microbiologically influenced corrosion (MIC) is corrosion affected by the presence or activity (or both) of microorganisms in biofilms on the surface of the corroding material. Many materials, including most metals and some nonmetals, can be degraded in this manner. Microbiologically mediated reactions can alter both rates and types of electrochemical reactions in a corrosion cell. These reactions influence general and localized corrosion, (inclusive of pitting and crevice corrosion), differential aeration cells, concentration cells, dealloying, and galvanic corrosion. Therefore, MIC investigations require microbiological, chemical, and metallurgical testing for proper diagnosis. The conclusion that MIC has taken place should be based on the preponderance of circumstantial evidence. Microorganisms are often resistant to many control methods and can pose a serious internal corrosion threat to pipelines.
This NACE standard test method applies to the internal surfaces of pipelines, and describes types of microorganisms, mechanisms by which MIC occurs, methods for sampling and testing for the presence of microorganisms, research results, and interpretation of test results. Sections 1 through 4 discuss the technical aspects of MIC. Sections 5 through 7 discuss field equipment and testing procedures. This standard is intended for use by pipeline operators, pipeline service providers, government agencies, and any other persons or companies involved in planning or managing pipeline integrity.
Portions of Sections 3 and 4 of this standard are excerpted from Peabody’s Control of Pipeline Corrosion, Chapter 14, “Microbiologically Influenced Corrosion.”1
This standard test method was prepared by Task Group (TG) 254, “Microbiologically Influenced Corrosion on Internal Surfaces of Pipelines: Detection, Testing, and Evaluation— Standard Test Method.” It was revised by TG 254 in 2016. TG 254 is administered by Specific Technology Group (STG) 35, “Pipelines, Tanks, and Well Casings.” This standard is issued by NACE under the auspices of STG 35.
This standard practice presents guidelines and procedures for use during risk assessment, mitigation, and monitoring of corrosion on underground, cathodically protected steel piping systems caused by proximity to alternating current (AC) power supply systems.
As shared right-of-way and utility corridor practices become more common, AC influence on adjacent metallic structures has greater significance, and corrosion due to AC influence becomes of greater concern. This standard is not intended to supersede or replace existing corrosion control standards, but rather to complement these standards when the influence of AC-powered systems becomes significant.
The effects of lightning and AC power transmission systems on human safety are not covered by this standard. However, the mitigation measures implemented for safety and system protection, as outlined in NACE SP0177, can also be used for AC corrosion control and are cited whenever feasible.
The original technical background for this standard is the NACE Technical Committee Report “AC Corrosion State-of-the-Art: Corrosion Rate, Mechanism, and Mitigation Requirements” prepared by NACE Task Group 327 and published by NACE in January 2010. Supplements to the current understanding of AC corrosion and criteria for this have been made in PRCI (1) reports published in October 2016.
This standard addresses typical power transmission frequencies up to 60 Hz only.
This standard was prepared by Task Group (TG) 430 on “AC Corrosion on Cathodically Protected Pipelines: Risk Assessment, Mitigation, and Monitoring” in 2018. TG 430 is administered by Specific Technology Group (STG) 05 on Cathodic/Anodic Protection and sponsored by STG 35 on Pipelines. This standard is issued by NACE under the auspices of STG 05.
This NACE standard establishes a standard test procedure for pack bed carburization of alloys used for ethylene manufacture. The pack bed carburization procedure is specified in this standard because it is simple to perform. The test specimen geometry chosen reflects the intent of the procedure to be used for evaluation of carburization of furnace tube alloys intended for ethylene manufacture.
This standard also establishes two recommended methods—combustion analysis and chemical etching—for measuring the relative carburization of alloys for tubes intended for service in ethylene manufacture, or for assessing the performance of these tubes after service. Application procedures for the two methods are defined in detail.
The combustion analysis method is preferred because it is quantitative. The chemical etching method is simpler and less expensive, but is only semi quantitative. Other methods considered and the reasons they are not recommended are discussed in Appendix A (nonmandatory).
The carburization measurement methods in this standard may be used independently from the pack bed carburization procedure when assessing the condition of tubes after service or when other carburization procedures have been performed.
This standard is intended to assist designers, operators, producers, fabricators, users, and testing laboratories in the selection of furnace tube alloys used for ethylene manufacture.
This standard was originally prepared in 1998 by Task Group (TG) T-5B-11, a component of Unit Committee T-5B on High-Temperature Materials Performance. It was reaffirmed in 2002 by Specific Technology Group (STG) 37, “Process Industry—High Temperature.” It was revised in 2006 by TG 124, “Furnace Tubes: Evaluating Carburization Resistance of Ethylene Cracking,” which is administered by STG 37. It was revised in 2014 by TG 124 and reaffirmed in 2018 by STG 37. This standard is issued by NACE International under the auspices of STG 37.
This standard test method is a colorimetric determination of low concentrations of phosphonate residuals in water from oil and gas production, water injection/disposal, and other industrial applications. This standard is maintained by Task Group (TG) 414.
This standard test method is a colorimetric determination of low concentrations of phosphonate residuals in water. Organic phosphonates are used as mineral scale and corrosion inhibitors in oil and gas operations, water injection/disposal operations, and other industrial applications. This test method is intended for use by oil and gas operators and service companies to determine residual phosphonate concentrations in waters that are treated with phosphonate inhibitors.
This test method was developed at Rice University under the direction of Dr. Mason Tomson with funding from the Gas Research Institute (GRI).
This standard was originally prepared by Task Group (TG) T-1D-52, a component of Unit Committee T-1D, “Corrosion Monitoring and Control of Corrosion Environments in Petroleum Production Operations” in 1999, and it was reaffirmed in 2005 by Specific Technology Group (STG) 31, “Oil and Gas Production—Corrosion and Scale Inhibition.” The standard was stabilized in 2018 by TG 414, “Review and Revise as Necessary NACE Standard TM0399-2005.” It is issued by NACE International under the auspices of STG 31.
This NACE standard test method establishes a test to evaluate and compare the corrosion protection that various internal plastic coatings afford oilfield tubular goods. Using this test method, random sections are tested with flowing water at a given velocity under controlled temperatures for a specified period of time. This standard includes a figure of the typical test apparatus used for this test method. This standard is maintained by Task Group 488.
This standard test method was written to provide manufacturers, applicators, and users of internal pipe coatings with a method of comparing the performance of these coatings. This method is not intended to correlate with any field performance but merely provides a means of comparing samples of internally coated tubing or line pipe under identical flowing water conditions.
This standard was originally prepared in 1983 by Work Group T-1G-6b of Unit Committee T-1G on Protective Coatings and Nonmetallic Materials for Oilfield Use. It was reviewed by T-1G-6 and reaffirmed by Unit Committee T-1G in 1988, 1993, and 2000, and in 2006 by Specific Technology Group (STG) 33 on Oil and Gas Production—Nonmetallics and Wear Coatings (Metallic). It was made a stabilized standard by Task Group (TG) 488, Review of NACE Standard TM0183 in 2018. This standard is issued by NACE International under the auspices of STG 33.
ABSTRACTIn refineries and oil and gas plants, air-cooled heat exchangers, so-called fin fan coolers, are fabricated from 22% Cr duplex stainless steels where type 300 series stainless steels would have problems with chloride pitting and chloride stress corrosion cracking (CSCC). Depending on application, limits are often specified for ferrite content and hardness (typically 35-65% for ferrite content and 320 HV maximum) during welding procedure qualification. Recent several cases of failures in hydroprocessing reactor effluent air cooler (REAC) system in refineries are now attracting worldwide attention to ferrite content and hardness in 22% Cr duplex stainless steel welds. In this study, welding trials were performed on 22% Cr duplex stainless steel UNS S32205 corner joints with different wall thickness similar to the top plate and tubesheet plate joint configuration used in a fin fan cooler header box. The effects of material thickness (15 mm, 25 mm, and 35 mm), weld heat input, and joint restraint during welding fabrication on ferrite content and hardness of the welds were evaluated. The results seem to suggest a need for careful re-evaluation of the upper limits of ferrite content and hardness for thick-wall 22% duplex stainless steel joint which are currently used.INTRODUCTIONDuplex stainless steels have a two-phase microstructure, approximately 50% ferrite and 50% austenite, and are often used in petroleum refineries and oil & gas plants where type 300 series stainless steels would have problems with chloride pitting and chloride stress corrosion cracking (CSCC). In recent years, plant users tend to prefer duplex stainless steels to type 300 series stainless steels considering the presence of chlorides in the external atmospheric environments. This trend has led to an increasing uptake of the use of these steels.The most commonly used grade of duplex stainless steel for air-cooled heat exchangers in petroleum refineries and oil & gas plants is 22% Cr duplex stainless steel (Alloy 2205; UNS S31803/S32205). When this steel is applied to welded components, limits are often specified for ferrite content and hardness (typically 35-65% for ferrite content and 320 HV maximum)1 during welding procedure qualification due to concerns that these may increase susceptibility to corrosion and cracking in service.
ABSTRACTErosion-corrosion, is a major problem in pulp/paper mill equipment. Erosion-corrosion in steels under caustic conditions is a challenging subject due to the particulate fluid with organics and non-Newtonian behavior. Fluid properties, liquor composition and process parameters affect corrosion rates in this regime. Studies have suggested that the flow may interfere with passive film formation in caustic conditions and significantly increase the corrosion rate.In order to better understand the mechanism of this corrosion process, electrochemical tests were performed on UNS G10180, UNS S31603 and UNS S32205, used in the construction of pulp/paper machinery components exposed to caustic environments. Rotating cylinder electrode (RCE) tests with linear polarization resistance (LPR) method were used to get instantaneous corrosion in a simulated white liquor (WL) solution with hard particles simulating conditions for the digesters or evaporators. Repassivation behavior of alloys under flow conditions was studied by using scratch tests. The results showed that G10180 was resilient at room temperature but corroded actively at elevated temperature, while S31603 showed sensitivity to flow especially at elevated temperature. S32205 provided good performance in the tested temperatures and environments without significant flow effects. Finally, a practical, qualitative measurement of “potential shift” after a scratch was introduced.INTRODUCTIONErosion-corrosion, defined as the loss of material under continuous, combined effects of mechanical and chemical environmental factors, is an important issue in the complex flow systems found in a number of chemical process industries.1-11 The recovery cycle, the pulper/repulper and even storage units are very important and essential pieces of the workings of a paper mill and can easily fall victim to the combined mechanical and chemical action of erosion-corrosion if improperly designed, used or monitored. However, the knowledge about erosion-corrosion in these systems is insufficient to provide scientifically justifiable methods to avoid equipment damage. This study is part of a broader effort to understand the erosion-corrosion mechanism and increase the reliability of materials used in the pulp and paper industry and beyond.
ABSTRACTEvaluation of corrosion inhibitors for high temperature (HT) upstream oilfield applications can be challenging due to fixed fluid volume testing typically encountered in laboratory testing. A series of laboratory testing methodologies were conducted to further elucidate the factors which affect laboratory corrosion inhibitor performance in high temperature conditions. Under certain HT conditions, inhibitor performance may be skewed due to testing effects which may occur in closed cell testing such as Fe2+ saturation and/or scaling of the test fluids which may artificially lower the overall general corrosion rate. This testing program was designed to minimize these effects and ensure that corrosion inhibition in laboratory testing is identified solely due to performance of the inhibitor. For these studies, corrosion measurements in stirred autoclaves were performed by linear polarization resistance (LPR) or with weight loss measurements in rotating cage autoclaves (RCA). Surface morphology of corrosion products, scale deposition and effects of localized attack were evaluated by microscopic evaluations. Factors affecting inhibited and uninhibited general corrosion rates measured in laboratory test environments such as brine composition, effect of scale inhibitor inclusion, effect of metal surface area to fluid volume ratio, and method of acid gas charging were evaluated.INTRODUCTIONAmine based film forming corrosion inhibitors (CI) have been used extensively to control internal corrosion experienced as a result of production of oil, gas, and produced water in upstream environments. Although extensive research in various test methods have shown the ability to qualify corrosion inhibitors at temperatures < 100°C, a better understanding of the parameters which affect corrosion processes at temperatures > 100°C is necessary.CO2-dominated fixed volume fluid testing has long been a challenge of laboratory corrosion inhibitor evaluations as brine chemistry, pH, concentration of Fe2+, etc. can change throughout the duration of the test affecting both the overall general corrosion rate and subsequent performance characteristics of the inhibitor.1 This phenomenon is especially evident in high temperature (HT) testing as elevated temperatures encourage the formation of passivating FeCO3 and/or mineral scales which can result in an overall artificial reduction of the corrosion rate.2-5 Closed cell laboratory testing relies on a fixed fluid volume in which accumulation of corrosion by-products can alter bulk fluid chemistry as well as the resultant steady state corrosion rate.1 Laboratory simulations differ from field conditions as the bulk fluid properties in the field will be less prone to significant changes in fluid chemistry encountered in fixed volume tests. Therefore, proper CI selection in laboratory evaluations should mimic as closely as possible the corrosive condition expected in the field.
Kim, Chuljung (Samsung Heavy Industries) | Hwang, HyangAn (Samsung Heavy Industries) | Oh, TaeJin (Samsung Heavy Industries) | Lim, ChaeSeon (Samsung Heavy Industries) | Jansen, Edward (American Bureau of Shipping / Technology) | Eliasson, Johnny (Chevron / Material and Corrosion) | Chaloner-Gil, Benjamin (Chevron / Material and Corrosion) | Quintero, Martin (Chevron / Material and Corrosion) | Shin, PyoungHwa (Pukyong National University) | Shon, MinYoung (Pukyong National University)
ABSTRACTOffshore platforms are operated for more than 30 years without re-docking in severely corrosive environment. Therefore, higher level of quality is required not only to reduce maintenance cost but also to keep long term service life time.In maintenance point of view, coating and surface preparation are matter of the most importance. Especially, water soluble salts contamination on steel surface can significantly affect adhesion strength at the interface of steel and coating.To study the effect of water soluble salts affecting long-term durability of carbon steels coated with epoxy paint, the carbon steel surface was contaminated by different soluble salt concentration. Based on NORSOK M-501 and ISO 20340 test method, sea water immersion and cathodic disbonding test were carried out for 6 months. Visual observation and pull off adhesion test were conducted. In addition, the phenomenon that the solute is accumulated on the contaminated boundary layer (Coffee Ring Effect) was studied.Consequently, the results show that 50 mg/m2 and less of salt contamination levels was closed to reaching an acceptable coating performance. Additionally, it was confirmed that the thicker coating showed the better adhesion property.INTRODUCTIONContamination in the form of sea salts is common in a marine atmosphere. If surfaces contaminated with sea salts are coated and later immersed, moisture will penetrate the coating film to the contaminants. At first, the contaminant attracts moisture, resulting in a saline solution. In order to thin solution more moisture penetrates the coating until equilibrium has been reached. Therefore, blistering will occur in these areas. This phenomenon, called osmotic blister, leads to the deterioration of paint system in a very short period of time.Off-shore platforms are operated more than 30 years without re-docking. Therefore, it is necessary to keep high quality coating performance for long-term operation period without maintenance.As a result of pre-analysis of paint specification for four oil major companies, it was confirmed that each company has different acceptance grade of salt contamination level and there was no correlation between design life time and soluble salt concentration shown in Table 1.
ABSTRACTResistance testing of low alloyed steel pipes to Hydrogen Induced Cracking (HIC) is performed according to NACE standard TM0284. Within the latest revision of this standard in 2016, fitness-for- purpose testing, where the test environment and partial pressures of gases appropriate to the intended application are selected, has been included. Mildly sour service conditions may require testing under less severe conditions. Compared to the standard test duration of 4 days, longer test durations up to 90 days can be required in the newly added test solution C.HIC tests have been performed for several SAWL large diameter pipes of grade X65-X80 designated for sweet or mildly sour environments at hydrogen sulfide partial pressures between 100 kPa and 0.5 kPa at different pH values between 3.3 and 5.8 in NACE TM0284 standard test solutions. For evaluation, the new ultrasonic procedure of NACE TM0284-2016 has been used as well as standard metallographic evaluation by equidistant sectioning of some specimens and determination of the CLR, CTR and CSR. Test results are compared after 4 days and the designated longer test durations. Based on the different test durations, material dependent HIC resistivity trends can be observed for the different pipe materials.INTRODUCTIONSteel pipelines designated for the transport of oil and gas containing wet hydrogen sulfide (H2S) are faced with the risk of sudden and severe cracking. In sour environments containing water and H2S, hydrogen atoms, originating from the anodic dissolution of the material, can diffuse into the steel and induce severe damage. Different forms of cracking may occur, such as Hydrogen Induced Cracking (HIC), Sulfide Stress Cracking (SSC) or Stress Oriented Hydrogen Induced Cracking (SOHIC).1.2 These cracks can often be difficult to detect in routine inspections and are thus regarded as a higher risk for integrity loss than weight-loss corrosion. Due to the sudden and unforeseeable appearance of these failure mechanisms it is in general necessary to use HIC resistant pipeline steel for all sour applications.